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Tamarack Valley Energy Ltd. Announces Record 2018 Financial and Operating Results Including 43% Increase in Total Adjusted Operating Field Netbacks, 20% Increase in Production and 22% Increase in Oil Reserves


TSX:TVE – CALGARYFeb. 27, 2019 /CNW/ – Tamarack Valley Energy Ltd. (“Tamarack” or the “Company“) is pleased to announce its financial and operating results for the three and twelve months ended December 31, 2018 and the results of its independent oil and gas reserves evaluation as of December 31, 2018, prepared by GLJ Petroleum Consultants Ltd. (“GLJ”).  Selected financial, operational and reserves information is outlined below and should be read with Tamarack’s audited consolidated financial statements (“Financial Statements”), management’s discussion and analysis (“MD&A”) as of December 31, 2018, which are available on SEDAR at www.sedar.com and on Tamarack’s website at www.tamarackvalley.ca. The Company’s annual information form (“AIF”) for the year ended December 31, 2018 will be filed on SEDAR and available on Tamarack’s website by close of business February 27, 2019.

2018 Financial and Operating Highlights

  • Maintained stable production volumes of 24,780 boe/d in Q4/18 relative to 24,765 boe/d in Q3/18, while investing only $25.8 million in capital expenditures, a $52.3 million reduction from the previous quarter.
  • Total adjusted operating field netback (previously referred to as “adjusted funds flow”; see “Non-IFRS Measures”) increased 43% in 2018 to $226.5 million ($0.99 per share basic and $0.97 per share diluted), from $158.4 million in 2017 ($0.70 per share basic and diluted).
  • In Q4/18, total adjusted operating field netback of $38.3 million exceeded capital spending of $21.0 million, net of acquisitions and dispositions, by $17.3 million, resulting in excess total adjusted operating field netback for the period, which was directed to debt repayment and continued funding of the Company’s active share repurchase program.
  • Year over year, achieved a 20% increase in production, and an 8% increase in the oil and natural gas liquids (“NGL”) weighting percentage, while spending $9 million less capital, after acquisitions and dispositions, than the mid-point of the Company’s previous capital guidance.
  • Full year 2018 net production and transportation expenses per boe were 6% lower relative to 2017, stemming primarily from increased production from the lower-cost Veteran area.
  • Tamarack’s continued increase in oil and liquids weighting through 2018 largely contributed to 16% higher operating netbacks (see “Non-IFRS Measures”) compared to 2017, further supported by improved pricing and lower transportation expenses per boe year over year.
  • Invested $219.2 million in total capital expenditures net of dispositions during 2018, which included drilling a total of 164 (158.2 net) wells, comprised of 129 (124.7 net) Viking oil wells, 19 (17.8 net) Cardium oil wells, 4 (4.0 net) Penny oil wells, 11 (10.7 net) Redwater oil wells, one exploratory vertical stratigraphic well and one (1.0 net) water source well.

2018 Reserve Highlights

  • Tamarack’s strategy to enhance value through increased oil weighting was evidenced by increases to the Company’s crude oil reserves which grew by 22% for total proved plus probable (“TPP”), by 15% for total proved (“TP”) and 10% for proved developed producing (“PDP”), respectively, over 2017.
  • Growth across all reserves categories on an absolute basis was achieved in 2018; increased TPP reserves by 11% to 101.6 million boe; increased TP reserves by 8% to 55.7 million boe; and increased PDP reserves by 2% to 31.8 million boe.
  • On a per share basis (basic), realized growth of 12% in TPP, 9% in TP and 3% in PDP reserves, demonstrating Tamarack’s continued focus on enhancing per share metrics.
  • Net asset value based on the net present values (discounted at 10%) of the TP and TPP reserves is $2.83and $5.95 per basic share, respectively. The net present value of reserves has been adjusted for net debt of $179.9 million but assumes no value for undeveloped land or infrastructure.
  • Achieved attractive capital efficiencies through the 2018 development program, generating a TPP finding and development (“F&D”) and finding, development and acquisition (“FD&A”) cost recycle ratio of 2.4x and 2.5x, respectively, and a TP F&D and FD&A cost recycle ratio of 1.5x and 1.6x based on the 2018 average operating field netback of $30.05/boe.
  • Crude oil weighting across reserves categories also increased to 58%, 55% and 52% for TPP, TP and PDP, respectively, compared to 54%, 52% and 49% for the same categories in 2017, driving oil and NGL weighting across all reserve categories to approximately 65% compared to 62% in 2017.
  • The Company replaced 144% of production on a TP basis and 214% on a TPP basis.
  • Achieved TPP F&D costs of $12.59/boe and TPP FD&A costs of $11.85/boe, both including the change in future development capital (“FDC”) contributing to reducing the realized three-year average TPP F&D costs to $15.10/boe and TPP FD&A costs to $16.75/boe, both including the change in FDC.
  • Based on 2018 average production of 24,237 boe/d, achieved a TPP reserve life index of 11.5 years.

Financial & Operating Results

 

Three months ended

Years ended

December 31,

December 31,

2018

2017

  %

change

2018

2017

  %

change

($ thousands, except per share)

Total Revenue

73,075

90,160

(19)

398,804

283,672

41

Adjusted operating field netback 1

38,346

57,583

(33)

226,475

158,383

43

Per share – basic 1

$ 0.17

$ 0.25

(32)

$ 0.99

$ 0.70

41

Per share – diluted 1

$ 0.17

$ 0.25

(32)

$ 0.97

$ 0.70

39

Net income (loss)

18,952

(12,525)

251

38,310

(13,924)

375

Per share – basic

$ 0.08

$ (0.05)

260

$ 0.17

$ (0.06)

383

Per share – diluted

$ 0.08

$ (0.05)

260

$ 0.16

$ (0.06)

367

Net debt 1

(179,880)

(173,180)

4

(179,880)

(173,180)

4

Capital Expenditures 2

25,798

35,516

(27)

226,251

192,302

18

Weighted average shares outstanding (thousands)

Basic

227,211

228,066

227,720

225,306

1

Diluted

232,066

228,066

2

233,561

225,306

4

Share Trading (thousands, except share price)

High

$ 5.20

$ 3.15

65

$ 5.20

$ 3.59

45

Low

$ 1.81

$ 2.49

(27)

$ 1.81

$ 1.96

(8)

Trading volume (thousands)

72,410

35,006

107

268,916

196,595

37

Average daily production

Light oil (bbls/d)

14,163

12,189

16

13,769

9,929

39

Heavy oil (bbls/d)

755

500

51

552

511

8

NGL (bbls/d)

1,485

1,459

2

1,398

1,547

(10)

Natural gas (mcf/d)

50,262

51,956

(3)

51,108

48,893

5

Total (boe/d)

24,780

22,807

9

24,237

20,136

20

Average sale prices

Light oil ($/bbl)

36.78

65.08

(43)

64.17

59.42

8

Heavy oil ($/bbl)

49.33

48.97

1

59.13

46.01

29

NGL ($/bbl)

33.72

44.03

(23)

41.89

32.38

29

Natural gas ($/mcf)

3.70

1.89

96

2.30

2.32

(1)

Total ($/boe)

32.05

42.97

(25)

45.08

38.60

17

Operating netback ($/Boe) 1

Average realized sales

32.05

42.97

(25)

45.08

38.60

17

Royalty expenses

(2.59)

(4.03)

(36)

(4.51)

(3.96)

14

Production expenses

(10.47)

(10.40)

1

(10.52)

(11.19)

(6)

Operating field netback ($/Boe) 1

18.99

28.54

(33)

30.05

23.45

28

Realized commodity hedging gain (loss)

0.04

1.53

(97)

(2.03)

0.77

(364)

Operating netback

19.03

30.07

(37)

28.02

24.22

16

Adjusted operating field netback ($/Boe) 1

16.82

27.44

(39)

25.60

21.55

19

 Notes:

(1)

Net debt, operating netback, operating field netback and adjusted operating field netback do not have any standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities. See “Oil and Gas Metrics” and “Non-IFRS Measures“.

(2)

Capital expenditures include exploration and development expenditures, but exclude asset acquisitions and dispositions.

2018 In Review

Through 2018, Tamarack delivered another year of exceptional performance supplemented by an unwavering commitment to enhancing per share and debt-adjusted per share value.  In each quarter, the Company met or exceeded expectations for production while remaining focused on driving costs down and achieving strong capital efficiencies.  Tamarack grew annual production volumes 20% in 2018 over 2017, averaging 24,237 boe/d (65% oil and NGL), compared to 20,136 boe/d (60% oil and NGL) following a successful 2018 drilling program combined with strong capital efficiencies.  The Company’s 2018 average annual production was at the mid-point of its 2018 average guidance range of 24,000 to 24,500 boe/d (66% oil and NGL).  In Q4/18, Tamarack achieved record production of 24,780 boe/d (66% oil and NGL) exceeding the Company’s lower end of its exit 2018 guidance range of 24,500 to 25,000 boe/d.

Consistent with historical practices during periods of volatility in commodity prices, Tamarack remains disciplined in its capital allocation and preservation of balance sheet strength.  This became critical during the final quarter of 2018 when an unexpected and extreme widening of Canadian crude oil price differentials severely reduced the Company’s realized price for its oil and NGL products.  In response to this, Tamarack elected to defer $7.4 million of the $28.4 million in capital spending that had previously been planned for acceleration from 2019 into Q4/18.  As such, the Company’s Q4/18 capital spending totaled $21.0 million net of acquisitions and dispositions, bringing its total 2018 capital investment to $226.3 million ($219.2 millionincluding acquisitions, net of dispositions).  Tamarack remains focused on drilling wells which are expected to payout in 1.5 years or less and estimates it has more than nine years of development within its current inventory.

During Q4/18, capital was directed to drill a total of 24 (23.2 net) Viking oil wells and one (1.0 net) water source well in the Veteran area.  Of these Viking oil wells, 19 (18.5 net) are expected to be brought on production in Q1/19, while five (4.8 net) of the drilled Viking oil wells were also completed, equipped and tied-in during the period.  Six of the Viking wells are future Veteran waterflood injection wells, which will produce to recover the capital costs until the commencement of the injection project in the first half of 2019.  In addition, Tamarack completed and brought on production 18 (17.8 net) Viking oil wells and one (1.0 net) Penny oil well that had been drilled in late Q3/18.

Despite the weakness in realized oil prices during Q4/18, Tamarack generated total adjusted operating field netback of $38.3 million ($0.17 per share basic and diluted), exceeding its capital spending, including acquisitions and net of dispositions, by $17.3 million for the quarter.  The Company elected to direct excess total adjusted operating field netback to debt repayment and continued funding of Tamarack’s active normal course issuer bid (“NCIB”).  For the full year 2018, adjusted operating field netback totaled $226.5 million($0.99 per basic share; $0.97 per diluted share), an increase of 43% over $158.4 million ($0.70 per basic and diluted share) in 2017.  Based on the forward curve price deck, the Company anticipates generating excess total adjusted operating field netback in 2019 to again fully fund its capital program, achieve 3-5% debt-adjusted production per share growth in Q4/19 over Q4/18 and have incremental funds remaining.  With this situation and by maintaining financial flexibility, Tamarack retains optionality to increase drilling activity, pursue tuck-in acquisitions, repay debt or continue share buybacks under the NCIB depending on the prevailing price environment.  Year-end 2018 net debt totaled $179.9 million, which represents a net debt to Q4/18 annualized adjusted operating field netback ratio of 1.2 times, compared to 0.8 times at December 31, 2017.

Tamarack’s oil and NGL weighting continued to increase through 2018 and averaged 65%, compared to 60% in 2017, and largely contributed to operating field netbacks of $30.05/boe, 28% higher than in 2017.  Tamarack’s average per boe sales price increased 17% year-over-year to $45.08/boe in 2018 from $38.60/boe in 2017 while net production and transportation expenses per boe declined by 6%.  The Company anticipates its oil and NGL weighting will range between 64 to 66% of total 2019 production.

During 2018, Tamarack purchased and cancelled 3,025,000 outstanding common shares under the NCIB program, for a total investment of $11.7 million.  The NCIB provides management a tool that can be employed when there is a perceived misalignment between the Company’s prevailing share price and the underlying current and future potential value of its assets. In addition, it helps to offset the potential for dilutive impact that may be associated with the exercise and settlement of options issued under Tamarack’s stock-based compensation program.  In addition to the NCIB, the Company purchased 1,803,592 outstanding common shares in the open market for $5.8 million, which are held in trust and used to settle RSUs upon future exercise, further supporting Tamarack’s per share metrics.

2018 Year-End Reserves Summary

Tamarack continued to generate attractive capital efficiency metrics in 2018, despite a very challenging Q4/18 crude oil price environment which has had a severely negative impact on operating netbacks for the period.  The Company’s full year 2018 operating field netback was more representative of the performance through the year, averaging $30.05/boe, and reflecting the strategic capital shift to projects with higher oil and NGL weighting.  Using the Company’s full year operating field netback, Tamarack generated a TPP F&D recycle ratio of 2.4x, 1.5x for TP, and 1.2x for PDP, and FD&A recycle ratios of 2.5x for TPP, 1.6x for TP and 1.2x for PDP.  The Company maintained a consistent approach to reserves booking, with TP reserves including only 140.6 net Veteran and Consort horizontal Viking oil wells, 103.2 net Redwater and Saskatchewan horizontal Viking oil wells and 47.5 net undeveloped horizontal Cardium oil locations. Further, the FDC for 2019, within GLJ’s 2018 reserves evaluation, of $126.8 million is materially lower than Tamarack’s 2019 capital expenditure guidance of $170 to $180 million. The total FDC on a TP basis was $381.6 million and on a TPP basis was $700.2 million.

Consistent with Tamarack’s core strategy, the Company continued to take a long-term approach to the allocation of capital and development of its asset base in 2018, including the Veteran waterflood project.  During the year, the Company invested $30.3 million in waterflood capital, including constructing pipelines for the planned injectors, drilling a water source well, commencement of the water handling upgrades to the Veteran oil battery, drilling nine wells as future injectors in the Veteran unit and drilling six wells to be converted into injectors in East Veteran in 2019.  The results of this capital investment have been conservatively recognized, as GLJ assigned probable reserves of 4.9 million barrels of oil associated with the waterflood, with no reserves yet reflected in the PDP or TP categories.  Excluding waterflood capital from PDP and TP F&D costs (including FDC) results in $22.28/boe and $17.62/boe, respectively and generates recycle ratios of 1.3x and 1.7x for the same respective categories.  In 2019, Tamarack plans to invest an additional $20 million to further the waterflood project, which will benefit the Company in future years by improving oil recoveries, reducing corporate decline rates and increasing production rates over time, while utilizing existing Tamarack-owned infrastructure.

The following tables highlight Tamarack’s 2018 year-end independent reserves assessment and evaluation prepared by GLJ with an effective date of December 31, 2018 (the “GLJ Report”).  The GLJ Report has been prepared in accordance with definitions, standards and procedures contained in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook.  All evaluations and summaries of future net revenue are stated prior to provision for interest, debt service charges or general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. The information included in the “Net Present Values of Future Net Revenue before Income Taxes” table below is based on an average of pricing assumptions prepared by three independent external reserves evaluators. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves.  Given Tamarack’s ongoing and extensive share buy-backs during 2018 under its NCIB and shares held in treasury to settle future restricted share unit (“RSU”) exercises, all per share reserves metrics below are based on basic shares outstanding.

Reserves Snapshot by Category:

PDP

TP

TPP

Reserves Added(1) (mboe)

9,319

12,737

18,957

Total Reserves (mboe)(2)

31,788

55,651

101,572

Reserves Replacement

105%

144%

214%

NPV10 BT ($mm)

$515.9

$820.8

$1,524.4

FD&A Cost per boe(3)

$24.47

$18.83

$11.85

Recycle Ratio(4)

1.2x

1.6x

2.5x

F&D Cost per boe (3)

$25.74

$20.23

$12.59

Recycle Ratio(4)

1.2x

1.5x

2.4x

Notes:

(1)

This number takes the difference in reserves year over year plus the production for the year.

(2)

Total reserves are Company Gross Reserves which exclude royalty volumes.

(3)

Including changes in FDC.

(4)

Based on 2018 operating field netback of $30.05 per boe.

Reserves Data (Forecast Prices and Costs) – Company Gross

RESERVES CATEGORY

CRUDE OIL(1)

CONVENTIONAL

NATURAL GAS(2)

NATURAL GAS

LIQUIDS

TOTAL OIL

EQUIVALENT

Gross

(Mbbls)

Net

(Mbbls)

Gross

(Mmcf)

Net

(Mmcf)

Gross

(Mbbls)

Net

(Mbbls)

Gross

(Mboe)

Net

(Mboe)

PROVED:

Developed Producing

16,484

14,629

75,954

70,112

2,645

2,111

31,788

28,426

Developed Non-Producing

1,081

962

8,928

7,902

61

54

2,630

2,333

Undeveloped

12,976

11,698

40,281

37,585

1,543

1,399

21,233

19,361

TOTAL PROVED

30,542

27,290

125,163

115,600

4,249

3,564

55,651

50,120

PROBABLE

28,609

23,857

86,930

79,982

2,824

2,399

45,921

39,585

TOTAL PROVED PLUS PROBABLE

59,151

51,146

212,093

195,581

7,073

5,962

101,572

89,706

Notes:

(1)

Heavy oil and tight oil included in the crude oil product type represents less than 3.1% of any reserves category and as such is immaterial.

(2)

Conventional natural gas amounts include coal bed methane, in amounts less than 0.1%.

(3)

Columns may not add due to rounding.

Net Present Values of Future Net Revenue before Income Taxes Discounted at (% per year)

 

RESERVES CATEGORY

0%

($000s)

5%

($000s)

10%

($000s)

15%

($000s)

20%

($000s)

Unit Value

Before Income

Tax

Discounted at

10% Per

Year(1)

($/Boe)

PROVED:

Developed Producing

681,815

590,082

515,863

459,947

416,912

18.15

Developed Non-Producing

55,510

44,239

37,438

32,842

29,474

16.05

Undeveloped

452,997

345,872

267,459

210,646

168,666

13.81

TOTAL PROVED

1,190,322

980,193

820,760

703,435

615,052

16.38

PROBABLE

1,407,444

962,460

703,627

540,753

431,402

17.77

TOTAL PROVED PLUS PROBABLE

2,597,765

1,942,653

1,524,387

1,244,188

1,046,454

16.99

Notes:

(1)

Unit values based on Company net interest reserves.

(2)

The prices used to estimate net present values are the average of those used by the largest independent industry reserve evaluators.

(3)

Columns may not add due to rounding.

Reconciliation of Company Gross Reserves Based on Forecast Prices and Costs

MBOE

FACTORS

Proved

Probable

Proved +

Probable

December 31, 2017

51,761

39,701

91,462

Extensions and Improved Recovery(1)

10,907

8,777

19,684

Technical Revisions

1,060

(2,875)

(1,816)

Acquisitions

1,128

527

1,655

Dispositions

0

0

0

Economic Factors

(358)

(210)

(567)

Production

(8,847)

0

(8,847)

December 31, 2018

55,651

45,921

101,572

Notes:

(1)

Reserves additions under Infill Drilling, Improved Recovery and Extensions are combined and reported as “Extensions and Improved Recovery”.

(2)

Columns may not add due to rounding.

(3)

Company Gross Reserves exclude royalty volumes.

Future Development Capital Costs

The following is a summary of GLJ’s estimated future development capital required to bring proved and probable undeveloped reserves on production.

Future Development Capital(1)

(amounts in $000s)

Total Proved

Total Proved + Probable

2019

91,721

126,768

2020

162,651

193,817

2021

87,219

156,685

2022 and Subsequent

39,978

222,902

Total Undiscounted FDC

381,570

700,174

Total Discounted FDC at 10% per year

323,279

563,488

Note:

(1)

FDC as per GLJ independent reserve evaluation effective December 31, 2018 based on GLJ forecast pricing.

FD&A Costs

2018

Three Year Average

(amounts in $000s except as noted)

TP

TPP

TP

TPP

FD&A costs, including FDC(1)(2)

Exploration and development capital expenditures (3)(4)

216,584

216,584

155,144

155,144

Acquisitions, net of dispositions(5)

2,627

2,627

160,913

160,913

Total change in FDC

20,572

5,414

62,160

111,433

Total FD&A capital, including change in FDC

239,783

224,625

378,217

427,490

Reserve additions, including revisions – Mboe

11,609

17,302

8,364

12,010

Acquisitions, net of dispositions(5) – Mboe

1,128

1,655

8,505

13,509

Total FD&A Reserves

12,737

18,956

16,869

25,519

F&D costs, including FDC – $/boe

20.23

12.59

19.90

15.10

Acquisition costs, net of dispositions – $/boe

4.33

4.12

24.90

18.22

FD&A costs, including FDC – $/boe

18.83

11.85

22.42

16.75

Notes:

(1)

While Nl 51-101 requires that the effects of acquisitions and dispositions be excluded from the calculation of finding and development costs, FD&A costs have been presented because acquisitions and dispositions can have a significant impact on the Company’s ongoing reserve replacement costs and excluding these amounts could result in an inaccurate portrayal of the Company’s cost structure. Finding and development costs both including and excluding acquisitions and dispositions have been presented above.

(2)

The calculation of FD&A costs incorporates the change in FDC required to bring proved undeveloped and developed reserves into production. In all cases, the FD&A number is calculated by dividing the identified capital expenditures by the applicable reserves additions after changes in FDC costs.

(3)

The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

(4)

The capital expenditures also exclude capitalized administration costs.

(5)

Includes capital spent in 2018 to develop the assets acquired during 2018.

(6)

Columns may not add due to rounding.

(7)

Calculations using Company Gross Reserves which exclude royalty volumes.

2019 Guidance

Our 2019 guidance remains unchanged with plans to invest between $170 and $180 million, funded entirely through adjusted operating field netback. This capital program is expected to result in production of 23,500 – 24,500 boe/d (64-66% oil and NGL). In the context of continued volatility in oil prices and supported by the Company’s exceptional operational execution, Tamarack remains committed to investing in longer-term projects, including the Veteran waterflood, which the Company expects will reduce the overall corporate decline rate in 2020 and enhance Tamarack’s sustainability.

Effective January 1, 2019 the Government of Alberta imposed production curtailments which, when combined with active production management and engagement from the producer community, have resulted in a significant narrowing of the differential into the early part of 2019.  The Company remains well positioned to withstand further crude oil price volatility given approximately 30% of its 2019 production is protected with hedges that include a US$60.00/bbl WTI put option and another approximately 3% is protected with fixed price contracts at US$64.60/bbl. Regardless, the Company will continue to closely monitor current and future commodity prices and price differentials. While the Company’s 2019 capital guidance assumes activity levels will be weighted evenly between H1 and H2 of 2019, the program timing for H1 has been designed to comply with the required production cuts.  Following expected stable production levels in H1/19 due to the mandatory volume curtailments, Tamarack anticipates realizing a meaningful ramp-up in production volumes during the second half of 2019, assuming no additional government intervention.

The Company’s 2019 guidance and assumptions are outlined below:

  • Annual average production between 23,500 – 24,500 boe/d (64-66% oil and NGL), with 2019 exit production estimated between 25,500 – 26,500 boe/d (64-66% oil and NGL);
  • Capital expenditures between $170 to $180 million to maintain the Alberta government’s mandatory production curtailments during Q1 of 2019;
  • Estimated year end 2019 net debt to Q4 annualized adjusted operating field netback ratio of approximately 1.0 times with an estimated $100 million of liquidity on existing credit facilities; and
  • Average 2019 commodity price assumptions of WTI US$50.00/bbl, Edmonton Par C$52.33/bbl, WTI / Edmonton Par differential of US$10.75/bbl, AECO $1.31/GJ and a Canadian/US dollar exchange rate of $0.75.

About Tamarack Valley Energy Ltd.

Tamarack is an oil and gas exploration and production company committed to long-term growth and the identification, evaluation and operation of resource plays in the Western Canadian Sedimentary Basin. Tamarack’s strategic direction is focused on two key principles: (i) targeting repeatable and relatively predictable plays that provide long-life reserves; and (ii) using a rigorous, proven modeling process to carefully manage risk and identify opportunities. The Company has an extensive inventory of low-risk, oil development drilling locations focused primarily in the Cardium and Viking fairways in Alberta that are economic over a range of oil and natural gas prices. With this type of portfolio and an experienced and committed management team, Tamarack intends to continue delivering on its strategy to maximize shareholder returns while managing its balance sheet.



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